1. Field of the Invention
The present invention relates generally to strategies for controlling fluid loss, and the formulation and use of fluid loss pills for use in oilfield applications.
2. Background Art
When drilling or completing wells in earth formations, various fluids typically are used in the well for a variety of reasons. The fluid often is water-based. For the purposes herein, such fluid will be referred to as “well fluid.” Common uses for well fluids include: lubrication and cooling of drill bit cutting surfaces while drilling generally or drilling-in (i.e., drilling in a targeted petroliferous formation), transportation of “cuttings” (pieces of formation dislodged by the cutting action of the teeth on a drill bit) to the surface, controlling formation fluid pressure to prevent blowouts, maintaining well stability, suspending solids in the well, minimizing fluid loss into and stabilizing the formation through which the well is being drilled, minimizing fluid loss into the formation after the well has been drilled and during completion operations such as, for example, perforating the well, replacing a tool, attaching a screen to the end of the production tubulars, gravel-packing the well, or fracturing the formation in the vicinity of the well, displacing the fluid within the well with another fluid, cleaning the well, testing the well, fluid used for emplacing a packer, abandoning the well or preparing the well for abandonment, and otherwise treating the well or the formation.
Brines (such as, for example, aqueous CaBr2) commonly are used as well fluids because of their wide density range and the fact that brines are typically substantially free of suspended solids. In addition, brines are often used in order to achieve a suitable density for use in well-drilling operations. Typically, the brines comprise halide salts of mono- or divalent cations, such as sodium, potassium, calcium, and zinc. Chloride-based brines of this type have been used in the petroleum industry for over 50 years; bromide-based brines, for at least 25 years; and formate-based brines, for only roughly the past ten years. One additional advantage of using brines is that brines typically do not damage certain types of downhole formations; and for formations that are found to interact adversely with one type of brine, often there is another type of brine available with which that formation will not interact adversely.
A variety of compounds are typically added to brine-based well fluids. For example, a brine-based well fluid may also include viscosifiers, corrosion inhibitors, lubricants, pH control additives, surfactants, solvents, and/or weighting agents, among other additives. Some typical brine-based well fluid viscosifying additives include natural polymers and derivatives thereof such as xanthan gum and hydroxyethyl cellulose (HEC). In addition, a wide variety of polysaccharides and polysaccharide derivatives may be used, as is well known in the art.
Some synthetic polymer and oligomer additives such as poly(ethylene glycol) (PEG), poly(diallyl amine), poly(acrylamide), poly(acrylonitrile), poly(aminomethylpropylsulfonate[AMPS]), poly(vinyl acetate), poly(vinyl alcohol), poly(vinyl amine), poly(vinyl sulfonate), poly(styryl sulfonate), poly(acrylate), poly(methyl acrylate), poly(methacrylate), poly(methyl methacrylate), poly(vinylpyrrolidone), poly(vinyl lactam), and co-, ter-, and quater-polymers of the following co-monomers: ethylene, butadiene, isoprene, styrene, divinylbenzene, divinyl amine, 1,4-pentadiene-3-one (divinyl ketone), 1,6-heptadiene-4-one (diallyl ketone), diallyl amine, ethylene glycol, acrylamide, AMPS, acrylonitrile, vinyl acetate, vinyl alcohol, vinyl amine, vinyl sulfonate, styryl sulfonate, acrylate, methyl acrylate, methacrylate, methyl methacrylate, vinylpyrrolidone, and vinyl lactam are also often used as viscosifiers.
One example of how a brine-based well fluid may be used in combination with the above listed polymers and oligomers is set forth below. When drilling progresses to the depth of penetrating a hydrocarbon bearing formation, special care may be required to maintain the stability of the wellbore. Examples of formations in which stability problems often arise include highly permeable and/or poorly consolidated formations. In these types of formations, a drilling technique known as “under-reaming” may be used. In under-reaming, the wellbore is drilled to penetrate the hydrocarbon bearing zone using conventional techniques. A casing generally is set in the wellbore to a point just above the hydrocarbon bearing zone. The hydrocarbon bearing zone then may be re-drilled, for example, using an expandable under-reamer that increases the diameter of the already-drilled wellbore below the casing.
Under-reaming is usually performed using special “clean” drilling fluids. Typical drilling fluids used in under-reaming are expensive, aqueous, dense brines that are viscosified with a gelling and/or crosslinked polymer to aid in the removal of formation cuttings. The high permeability of the target formation, however, may allow large quantities of the drilling fluid to be lost into the formation. Once the drilling fluid is lost into the formation, it becomes difficult to remove. Calcium and zinc bromide brines can form highly stable, acid insoluble compounds when reacted with the formation or substances contained therein. This reaction may reduce the permeability of the formation to any subsequent out-flow of targeted hydrocarbons. One of the most effective ways to prevent such damage to the formation is to limit fluid loss into the formation.
Providing effective fluid loss control without damaging formation permeability in completion operations has been a prime requirement for an ideal fluid loss-control pill. Conventional fluid loss control pills include oil-soluble resins, calcium carbonate, and graded salt fluid loss additives that have been used with varying degrees of fluid loss control. These pills achieve their fluid loss control from the presence of solvent-specific solids that rely on filter-cake build up on the face of the formation to inhibit flow into and through the formation. However, these additive materials can cause severe damage to near-wellbore areas after their application. This damage can significantly reduce production levels if the formation permeability is not restored to its original level. Further, at a suitable point in the completion operation, the filter cake must be removed to restore the formation's permeability, preferably to its original level.
A major disadvantage of using these conventional fluid loss additives is the long periods of clean-up required after their use. Fluid circulation, which in some cases may not be achieved, is often required to provide a high driving force, which allows diffusion to take place to help dissolve the concentrated build up of materials. Graded salt particulates can be removed by circulating unsaturated salt brine to dissolve the particles. In the case of a gravel pack operation, if this occurs before gravel packing, the circulating fluid often causes sloughing of the formation into the wellbore and yet further loss of fluids to the formation.
If removal is attempted after the gravel pack, the gravel packing material often traps the particles against the formation and makes removal much more difficult. Other particulates, such as the carbonates can be removed with circulation of acid, however, the same problems may arise. Oil-soluble resins, carbonate and graded salt particulate will remain isolated in the pores of the formation unless they are in contact with solvent. In the cases where the solid materials cover a long section of wellbore, the rapid dissolution by solvent causes localized removal. Consequently, a thief zone forms and the majority of the solvent leaks through the thief zone instead of spreading over the entire wellbore length.
The use of conventional gel pills such as linear viscoelastic or heavy metal-crosslinked polymers in controlling fluid loss requires pumping the material through large-diameter tubing because of high friction pressures. These materials are typically prepared at the well site.
Among the linear polymers used to form fluid loss control pills is hydroxyethylcellulose (HEC). HEC is generally accepted as a polymer fluid affording minimal permeability damage during completion operations. Normally, HEC polymer solutions do not form rigid gels, but control fluid loss by a viscosity-regulated mechanism. Such polymer fluids may penetrate deeper into the formation than crosslinked polymers. Permeability damage may increase with increasing penetration of such viscous fluids.
According to conventional wisdom, in high permeability reservoirs, a highly crosslinked gel is needed to achieve good fluid loss control. Though HEC is known for its low residue content, it is difficult to crosslink particularly in regards to on-site or in situ formulations. However, according to M. E. Blauch, et al., in SPE 19752, “Fluid Loss Control Using Crosslinkable HEC in High-Permeability Offshore Flexure Trend Completions,” pages 465-476 (1989), while there are chemical methods to crosslink standard HEC, these methods have generally been found to be inapplicable to most completion practices.
Therefore, much effort has been expended to modify HEC to make it more easily crosslinkable, which adds to the expense and in some cases complexity of such systems. U.S. Pat. No. 4,552,215 to Almond, et al., discloses a cellulose ether which is chemically modified to incorporate pendant vicinal pairs of hydroxyl groups which assume or can assume cis geometry. These modified celluloses can be crosslinked by borate or zirconium (IV) metal ions and are useful for fluid loss control.
In SPE 29525, “A New Environmentally Safe Crosslinked Polymer for Fluid loss Control,” pages 743-753 (1995), R. C. Cole, et al., disclosed a polymer which has been prepared by grafting crosslinkable sites onto an HEC backbone. The polymer can be transformed into a rigid, internally crosslinked gel if the pH of the solution is adjusted from acidic to slightly basic through the use of a non-toxic metal oxide crosslinker. As stated in SPE 29525, there are no divalent or trivalent metals associated with the polymer or included in its crosslinking chemistry.
This dispersion, acidification, hydration, and yielding of the polymer and the addition of salt may be carried out on location at the well-site where it is to be used, or it can be carried out at another location than the well-site. If the well-site location is selected for carrying out this step, then the hydrated and yielded polymer and the salt can immediately be dispersed in a brine, such as, for example, a 14.2 ppg CaBr2-based brine, the crosslinkant activator can immediately be added, and the crosslinked product can immediately be emplaced in the well either through coiled tubing or through utilizing a process referred to as “bull-heading”.
As mentioned above, the dispersion, acidification, hydration, and yielding of the polymer and the addition of salt may be carried out either on location or at a “pre-manufacture” site remote from the well-site. There, the hydrated and yielded polymer and the salt is dispersed in a brine, such as, for example, a 14.2 ppg CaBr2-based brine, the crosslinkant activator is added, and the crosslinked product is packaged in 5-gallon buckets which are palletized and shipped to the well-site.
Regardless of where the crosslinked, salt-weighted, product is pre-manufactured, it may, optionally, be dispersed in a carrier fluid in the form of “chunks” of irregularly shaped crosslinked material, wherein said chunks have volumes on the order of ½ to 2 cubic inches. The carrier fluid for this process may be a brine, such as, for example, a 14.2 ppg CaBr2-based brine, or any other brine, or, alternatively, it may be a viscosified brine, such as, for example, a 14.2 ppg CaBr2-based brine containing a linear (i. e., un-crosslinked) polymer, such as, for example, HEC or any other “natural” or “synthetic” polymer. Once the slurry of chunks of crosslinked, salt-weighted, material in a brine or viscosified brine carrier fluid is created, it is immediately pumped down the well either through coiled tubing emplacement or “bull-heading”.
The crosslinking is effected by the use of a slowly soluble, non-toxic metal oxide. The resulting crosslink fluid is said to demonstrate shear-thing-thinning and re-healing properties that provide for easy pumping. The re-healed gel is said to provide good fluid loss control upon placement. The polymer is referred to as a double-derivatized HEC (DDHEC). Instead of being a dry polymer in a bag, the DDHEC is a dispersion in an environmentally safe, non-aqueous, low-viscosity carrier fluid. The non-flammable carrier fluid is initially soluble in most brines. Hydration occurs only at specific, highly acidic conditions. At near neutral pH, the DDHEC polymer is dispersed into the mixing brine. When required, the pH is lowered, encouraging hydration and yielding of the polymer to rapidly occur.
U.S. Pat. No. 5,304,620 discloses a gel of a graft copolymer of a hydroxyalkyl cellulose, guar or hydroxypropyl guar prepared by a redox reaction with vinyl phosphonic acid. The gel is formed by hydrating the graft copolymer in an aqueous liquid containing at least a trace amount of at least one divalent cation. U.S. Pat. No. 5,439,057 discloses the use of a crosslinking agent comprising at least one titanium IV ions, zirconium IV ions, aluminum III ions, and antimony V ions to crosslink a polysaccharide polymer and form a gel.
In SPE 36676, “Development and Field Application of a New Fluid Loss Control Material,” pages 933-941 (1996), P. D. Nguyen, et al., disclosed grating crosslinked, derivatized hydroxyethylcellulose (DDHEC) into small particulates kept in a brine solution. Details of the chemistry and properties of the un-grated crosslinked DDHEC were described in SPE 29525 discussed above.
In SPE 36676, crosslinked DDHEC was placed in a pressure chamber to which a perforated disk, cylinder or screen was attached to its end. Air was introduced at the other end of the pressure chamber to push the crosslinked material into and through the grating device and shredded. The shredded material is provided as a slurry concentrate and is said to be stable enough to store in this form. The slurry concentrate is then dispersed in a completion fluid.
U.S. Pat. No. 5,372,732 to Harris, et al., discloses a dry, granulated, delayed crosslinking agent for use as a blocking gel in a workover operation comprising a borate source and a water-soluble polysaccharide comprising at least one member selected from the group of guar gum, hydroxypropylguar and carboxymethylhydroxypropylguar. The blocking gel forms a relatively impermeable barrier cordoning off the production zone from the area undergoing the workover operation. The crosslinking agent is prepared by dissolving one of the water-soluble polysaccharides identified above in an aqueous solution. To the aqueous solution is added a borate source to form a crosslinked polysaccharide. The borate-crosslinked polysaccharide is then dried and granulated.
The delayed crosslinking agent is admixed with an aqueous gel containing a second-water soluble polysaccharide solution. As is well known in the art, the borate crosslink is a reversible crosslink in that the borate/polymer crosslinkage at basic pH is in equilibrium with the borate ion and polymer crosslink sites (i.e., cis-oriented hydroxyl groups), wherein the borate ion detaches from one site and then reattaches to another or the same site of the same or different polymer. Such crosslinked polymers are said to be self-healing since if the crosslink is broken it will reform at the same or different location. However, it is also known that HEC is not crosslinkable with borates. This is one reason why HEC has been derivatized by others to incorporate hydroxyl groups which can be in a cis orientation relative to one another so that borate-crosslinking can subsequently be initiated or derivatized by yet others to incorporate vinylphosphonate groups which can be crosslinked with the addition of magnesium oxide.
What is still needed, however, are improved fluid loss pills, especially those of greater density so that as fluid loss from the wellbore is occurring, the fluid loss pill can drop through the fluid in the well and sink towards and be drawn to the point of fluid loss or leakage from the wellbore into the formation, whereupon, if the fluid loss pill is a highly viscous, gelled or crosslinked, weighted pill, the fluid loss pill will lay across the rock face and seal off so that further fluid loss is prevented or minimized without the fluid loss pill penetrating to any significant extent into the porous medium comprising the petroliferous formation.